Renewable Hydrogen in Fukushima and a Bridge to the Future
Byon October 19, 2017
Economic implementation of a new technology requires a bridge of practical actions that stretch from the settled status quo to the desired future state. Creating such a bridge is often difficult, and is made the more so when the new technology suffers a cost disadvantage vs. the incumbent. Such a disadvantage must generally be overcome by government subsidies and/or regulations – which tend to be complex and uncertain by their very nature. Proponents of the new technology must therefore employ every available expedient to minimize the cost gap. This is the implicit argument of those who foresee an important role for ammonia in the hydrogen energy economy. It is critical to take advantage of ammonia’s favorable economics as an energy carrier whenever possible, especially if government support is involved.
These reflections were brought to mind by an August 1, 2017 announcement from the Japan Government’s New Energy and Industrial Technology Development Organization (NEDO) that it will proceed with funding for the construction of a hydrogen production plant in Namie Township, about ten kilometers from the site of the Fukushima nuclear disaster. The project’s budget is not mentioned, but the installation is projected to be “the largest scale in the world” — in other words, a real bridge to the future and not a demonstration project.
The project no doubt has a variety of motivations, not least the symbolic value of a renewable hydrogen plant rising in the shadow of the Fukushima Daiichi nuclear station. In economic terms, though, it appears to be a dead end. This is unfortunate because a similarly conceived project based on ammonia could be a true bridge-building step that aligns with leading-edge developments elsewhere in the world.
The project developers are Tohoku Electric, Toshiba, and the industrial gas company Iwatani. The hydrogen will be produced by electrolyzers powered by a 20 MW photovoltaic farm installed on the same site. Tohoku will feed some of the electricity into its distribution grid. The electrolyzers, with a cumulative power rating of 10 MW, will be used as an energy storage mechanism. Equipment selection is not mentioned but it is fair to assume that Toshiba will supply its recently introduced alkaline water electrolyzers that can produce nine kg of hydrogen per hour. The plant will produce 900 tonnes of hydrogen per year.
The scale of the plant contrasts with a 100 MW plant announced by Nel Hydrogen (an NH3 Fuel Association sponsor) in June 2017 that will be built for the French company H2V. Like the NEDO plant, it will come on line in 2020. Nel’s agreement with H2V calls for “seven to eight” additional plants of this scale to be constructed in quick sequence after the first one. Nel is also discussing a 400 MW plant, equipped with electrolyzers that can produce 44 kg of hydrogen per hour, with an “international industrial company.”
The difference in scale between the 10 MW Japanese plant and the 100 MW French plant is the first factor that will undermine the economics of the Namie project. Earlier in 2017, IEA analyst Cédric Philibert modeled the economics of electrolyzer plants to determine the cost of hydrogen produced under various scenarios (covered here by Ammonia Energy). Under currently prevailing design parameters, the capital cost of electrolyzers is about $850 per kW of power capacity. Philibert estimates that that cost will fall to $450 per kW for Nel’s 400 MW plant. The effect of this difference on the cost of hydrogen is $0.20-$0.30 per kilogram. This is for a commodity whose baseline production cost is $1.00 per kg (via large-scale steam-methane reforming with natural gas priced at approximately $4.00 per GJ and downstream logistics excluded).
The next problem for the Namie plant is the nature of its electricity source. Philibert’s analysis indicates that the price of electricity needs to be $30 per MWh or less if hydrogen is to be produced at a competitive cost. At 20 MW, the Namie solar farm barely qualifies as utility scale, and as such is unlikely to produce a levelized cost of electricity that is even close to the $30 benchmark. More significantly, Philibert argues that electrolyzer plants must have high capacity utilization to be competitive. For green hydrogen production, this is likeliest if two or more sources of renewably generated electricity are used. A plant whose electricity is priced at $60 per MW and whose capacity utilization is 50% (an optimistic assumption with a single source of renewable electricity) will produce hydrogen at a cost of approximately $3.40 per kg, 240% higher than the benchmark. By contrast, the H2V plant, which is being deployed as a profit-making venture (albeit with help from the French tax code), will be powered with electricity from both solar and wind installations.
Yet another negative economic factor is downstream logistics. Iwatani plans to liquefy the hydrogen before transporting it. Iwatani holds about two thirds of Japan’s industrial hydrogen market, delivering about a third of its volume in liquid form. In 2014, the Nikkei Asian Review reported that Iwatani was selling hydrogen – unprofitably — for ¥1,100 per kg ($10.00 at current exchange rates). Assuming refinery production of the hydrogen, transportation is clearly adding a significant increment of cost. By contrast, the H2V hydrogen plants will be sited in such a way that they can inject their hydrogen directly into France’s natural gas distribution system.
An Ammonia-Based Alternative
An alternative, ammonia-based scenario could involve a plant of similar scale to the Namie installation that is supplied by renewable electricity derived from multiple sources with complementary diurnal generation profiles. This scenario is close to one that was modeled earlier this year by the Dutch research agency Institute for Sustainable Process Technology (ISPT) as part of a ground-breaking feasibility study (covered here by Ammonia Energy). As described in the study’s final report, “In this option, electricity produced by means of a base load source of CO2-free electricity (e.g. geothermal or hydro) is converted into H2 by means of electrolysis and subsequently converted into NH3. Then the NH3 is transported to Eemshaven by means of seagoing vessels. In the base case an electricity price of 25 EUR/MWh(e) [$30] is taken . . . [and a] 500 MWe (input) electrolyser case has been used.”
The study concluded that the cost of the ammonia produced would be “between 365 and 500 EUR/ton, and with a combination of optimistic assumptions on CAPEX and power price, a NH3 cost of 260-370 EUR/ton can be achieved.”
It should be noted that stakeholders from a number of countries are working on the concept of “distributed ammonia production” at relatively small plants that are powered with local generation resources, similar to the Namie concept. The Dutch engineering firm Proton Ventures, for example, has studied ammonia plants with an annual capacities ranging from 1,000 to 20,000 tonnes of ammonia (equivalent to 180-3,600 tonnes of pure hydrogen, the same order of magnitude as the 900 tonne/year Namie plant). (Proton Ventures Managing Director Hans Vrijenhoef is a member of the NH3 Fuel Association’s Board of Advisors.)
Enabling Fuel Cell Vehicles
The intended use of the Namie plant’s hydrogen is to power fuel cell vehicles (FCVs). FCVs today are a textbook example of a virtuous technology that lacks a bridge to the sustainable future. As discussed in a previous Ammonia Energy post, in Japan the vehicles cost more than comparable offerings even with government subsidies. The fuel costs so much more that the gap can scarcely be closed even with the superior energy efficiency of fuel cells. And fueling stations, currently very few and far between, are being rolled out at a slow pace.
The likeliest bridge to a FCV-friendly future might be a fueling station price of green hydrogen that is comparable on a per-MJ basis to incumbent light-duty vehicle fuels. This would allow the superior fuel efficiency to create operating economies for the vehicle owner that could offset the up-front price premium of the vehicle itself. Such a circumstance could stimulate market uptake which in turn could stimulate more rapid roll-out of fueling stations.
Petrol in Japan is currently priced at ¥131 per liter which translates to ¥4.1 per MJ. Hydrogen at ¥1,100 per kg translates to ¥7.8 per MJ, 90% higher than the figure for petrol. The cost of green ammonia in the basic ISPT scenario is ¥3.1 per MJ, and ¥2.3 per MJ in the optimistic scenario, 24% and 44% less than the petrol figure, respectively. Such savings might be enough to start a virtuous cycle of FCV uptake.
It should be emphasized that the ISPT study was based on estimates for costs as they could evolve by the early 2020s. But this is the point. Projecting technical capabilities and costs is one of the essential skills needed to build a bridge to the future. This is the only way that likely dead ends can be distinguished from building blocks that could carry us toward a sustainable outcome.
Map image courtesy of Kahoku Shimpo Publishing Co.